Conventional, oil recovery involves drilling a well and pumping a mixture of oil and water from the well. Oil is separated from the water and the water is usually injected into a sub-surface formation. Conventional recovery works well for low viscosity oil. However, conventional oil recovery processes do not work well for higher viscosity, or heavy, oil.
Enhanced Oil Recovery (EOR) processes employ thermal methods to improve the recovery of heavy oils from sub-surface reservoirs. The injection of steam into heavy oil bearing formations is a widely practiced EOR method. Typically, several tonnes of steam are required for each tonne of oil recovered. Steam heats the oil in the reservoir, which reduces the viscosity of the oil and allows the oil to flow to a collection well. After the steam fully condenses and mixes with the oil the condensed steam is classified as produced water. The mixture of oil and produced water that flows to the collection well is pumped to the surface. Oil is separated from the water by conventional processes employed in conventional oil recovery operations.
For economic and environmental reasons it is desirable to recycle the water used in steam injection EOR. This is accomplished by treating the produced water and directing the treated feedwater to a steam generator or boiler. The complete water cycle includes the steps of:                injecting the steam into an oil bearing formation,        condensing the steam to heat the oil whereupon the condensed steam mixes with the oil to become produced water,        collecting the oil and produced water in a well,        pumping the mixture of oil and produced water to the surface,        separating the oil from the produced water,        treating the produced water so that it becomes the steam generator or boiler feedwater, and        converting the feedwater into steam, which has a quality of approximately 70% to nearly 100%, for injecting into the oil bearing formation.        
Several treatment processes are used for converting produced water into steam generator or boiler feedwater. These processes typically remove constituents which form harmful deposits in the boiler or steam generator. These water treatment processes used in steam injection EOR typically do not remove all dissolved solids, such as sodium and chloride.
The type of steam generator that is most often used for steam injection EOR is a special type called the Once-Through-Steam-Generator (OTSG). The OTSG converts approximately 80% of the feedwater to steam. The remaining 20% of feedwater is discharged from the OTSG as a liquid mixed with the steam. This steam and water mixture is defined as 80% quality steam. While some OTSG designs can produce 85% or 90% quality steam and other designs are limited to 70% or 75% quality steam, it is a common feature for OTSGs used in EOR that some amount of water is required in the discharged steam to keep the entire steam generator heat transfer surface wetted. The OTSG which produces approximately 80% quality steam is appropriate for some steam injection EOR operations. First, unlike conventional industrial boilers, an OTSG can accept feedwater that has dissolved solids that are not removed by the water treatment process. These solids are flushed from the steam generator as residual dissolved solids in the 20% of feedwater that is not converted to steam. Secondly, 100% of the output from the OTSG is injected because it is acceptable to inject 80% quality steam into some heavy oil bearing formations.
For some EOR operations an OTSG that generates 80% quality steam is adequate. However, there are cases where generating 80% quality steam is not adequate. This is especially true for oil bearing formations where oil is bound or contained in sand deposits such as widely found in the Alberta, Canada region. In such cases, oil is typically recovered using what is referred to as a steam assisted gravity discharge (SAGD) process, and in SAGD processes, steam quality on the order of 70%-80% will not work to efficiently and effectively recover oil.
The SAGD process was developed for in-situ recovery of oil from oil sands deposits located in the Province of Alberta, Canada. The SAGD process requires a high quality steam. Indeed, in the past, most SAGD process have required near 100% quality steam. The requirement for such a high quality steam presents a challenge because it is not possible to produce high quality steam using a conventional OTSG. On the other hand, using a conventional industrial boiler has its drawbacks. While high quality steam can be achieved, the feedwater to such industrial boilers must be extensively treated.
The high quality steam required for the SAGD process is usually produced by directing 80% quality steam from the OTSG into a steam separator. The steam separator produces two streams. The first stream is a high quality steam, typically near 100% quality steam. The second stream is a liquid blowdown stream that contains the residual dissolved solids that were in the feedwater to the steam generator. This liquid blowdown stream is typically depressurized through pressure reducing stations, which might or might not include heat recovery, and then recycled to the water treatment process.
The liquid blowdown stream from the steam separator of a typical SAGD operation, which uses physical/chemical treatment and ion exchange for treating the produced water, is at least 20% of the feedwater flow and has been reported as high as 30%. The equipment required to process this blowdown stream represents a capital expense that provides no value in the oil recovery process. The heat recovery techniques which are employed to minimize the heat lost from the liquid blowdown stream from the separator do not recover 100% of the heat, and the liquid blowdown stream represents an operating cost that has no value in the oil recovery process. Another capital cost impact is that the water treatment system capacity must be increased by at least 25% to accommodate for the liquid blowdown stream from the steam separator.
An alternative for treatment of produced water that removes many of the dissolved solids is evaporation of the produced water. Distillate from the evaporator becomes the feedwater for a packaged boiler, for example. This process has the advantage of producing a higher quality feedwater for steam generation. However, even high quality distillate has some dissolved solids. These solids tend to accumulate in a packaged boiler. All packaged boilers require a blowdown stream to purge the dissolved solids that are present in the distillate. For a typical evaporator distillate of 2 ppm TDS comprised of 0.04 ppm hardness as CaCO3 and a packaged boiler operating at 1200 psig, the solubility limits of Ca(OH)2 and CaCO3 requires a blowdown of approximately 5%. Typically this blowdown stream is recycled to the water treatment system.
An OTSG can be utilized in a heavy oil recovery process that utilizes evaporation to treat feedwater for steam generation. If an OTSG is used in such a process, the steam quality will still be substantially less than 100% and a high pressure liquid blowdown stream is still required. This is due to the fact that conventional OTSGs require water to wet the heat transfer surfaces. Therefore, when an OTSG is utilized with evaporator distillate as feedwater, a steam separator is required and that gives rise to increased capital cost and operating cost.
Therefore, with either an OTSG or a boiler, a pressurized blowdown waste stream is created. In order to accommodate the blowdown waste stream, equipment is required to reduce the pressure of the blowdown waste stream, recover heat from the blowdown stream, and to channel the blowdown waste stream. This increases both capital and operating costs. In addition, these blowdown waste streams carry substantial energy that is lost. Finally, in many applications, these blowdown waste streams would comprise 5% to 20% of the feedwater to the OTSG or boiler, which is recycled for treatment. This effectively reduces the capacity of the treatment facility by 5% to 20%, which of course means that to compensate for treating these blowdown waste streams, the capacity of the treatment facility must be increased by 5% to 25%. This results in additional capital outlays and ongoing operating costs.